Various methods are well known to stimulate production of crude oil and natural gas from wells drilled in reservoirs of low permeability, although emphasis has been placed on hydraulically fracturing such formations with various liquids, such as native crude oil, with or without propping agents, such as sand, suspended therein. The hydraulic pressure applied to such low permeable formations creates tensile stresses in the rock of the formation surrounding the well bore and these stresses causing splitting, parting or fracturing of the rock. The initially formed fractures or channels are then extended by the injection of fluids containing propping agent to be deposited in the fractures. When the pressure is released, the propping agent deposited in the fractures hold the fractures open, leaving channels for reservoir fluid flow. The concentration of propping agent in the fluid is of significance because it determines the final thickness of the fractures. Typical prior art references disclosing such techniques include the following U.S. patents: Bullen, U.S. Pat. No. 3,664,422, McKinnel, U.S. Pat. No. 3,561,533; Gomory, U.S. Pat. No. 3,363,691; Marx, U.S. Pat. No. 3,136,361; Zingg et al., U.S. Pat. No. 3,842,910; Henry, U.S. Pat. No. 3,245,470; Trott, U.S. Pat. No. 2,859,821; and Kerver et al., U.S. Pat. No. 3,138,205.
Hydraulic fracturing with foam, however, is only a recent development. A process using a foam composition to fracture is disclosed in the Blauer et al. U.S. Pat. No. 3,937,283, in an article by Bullen appearing in the July 22, 1974 issue of "Oilweek" and a paper by Blauer and Kohlhaas entitled "Formation Fracturing with Foam" SPE 5003. These documents disclose a making of a fracturing foam by blending sand into jelled water and treating the slurry with a surfactant. The fluid pressure is increased with a conventional pump after which a gas, such as nitrogen or carbon dioxide, is injected into the fluid at which point a high pressure foam is created. This foam is then injected into the well.
The use of a foam as a fracturing fluid has a number of advantages. The foam has a low fluid loss and hence the fracture treatment is more efficient and since larger-area fractures are created with the same treatment volume, formation damage is minimized because little fluid invades the formation. Reduction of fracture conductivity is also minimized. Theoretically, the foam has a high sand-carrying and sand-suspending capability whereby a greater amount of sand will remain suspended in the fluid until the fracture starts to heal. Because more sand can be carried to the fracture, the propped fracture area to the created fracture area ratio theoretically approaches one. In addition, the sand does not settle quickly in the well bore during unplanned shut-downs during the treatment. The foam has a high effective viscosity permitting the creation of wider vertical fractures and horizontal fractures having greater area. The foam has a low friction loss which reduces the hydraulic horsepower necessary for injection and permits treatment of many wells down tubing. Since the foam has a low liquid content, the hydraulic horsepower necessary for injection is reduced which results in low hydrostatic head which, in turn, results in an underbalanced condition soon after opening the well thereby minimizing fluid entry and formation damage. Due to essentially zero fluid leakoff, a greater increase length of hydraulic fracture penetration into the formation is possible. Experience has shown that the cost of using foam for moderately deep wells is less than or the same as conventional techniques.
Unfortunately, the cost for using foam produced pursuant to the prior art has at least one major handicap, namely, the maximum proppant concentration obtainable is quite low. Conventional hydraulic fluids can achieve sand concentrations of 6 to 8 lbs. of sand per gallon of carrying fluid. Typical figures for concentration of proppant during the formation of the foam using a method taught in the Blauer et al patent includes a heavy gel with a maximum concentration of 6 to 8 lbs. of proppant per gallon of gel. However, when the liquid is foamed, the gas expands the liquid to approximately four times the original volume of gel. The net result is that the sand-foam concentration is reduced to about 2 lbs. per gallon. As a result, the conventional foam process is not as useful to industry as it could be.
Most of the conventional methods of fracturing use sand as a propping agent because of its availability, its low cost, ability to easily grade and size the sand particles, its chemical stability, its low interference with well activity, and its ability when in the crevices to withstand the tremendous pressures from the overburden when the fluid pressure is relieved. However, sand is also a highly abrasive substance and consequently specially designed equipment must be used. Rugged pumps and tanks are now available which can inject slurries with sand-fluid ratios as high as 9 lbs. per gallon. However, this concentration of sand is insufficient to provide a foam fracturing fluid that has the desired concentration of sand or propping agent. Because of the difficulty of pumping and otherwise handling large quantities and large flow rates of sand slurries, it is not possible to increase the initial sand concentration to much greater than 8 lbs. per gallon. Thus, there is a great need and a large demand for a foam fracturing fluid that has a high concentration of sand or other propping agent and a means for introducing the fracturing fluid at the high well head pressures required to cause fracturing.